1. Field of the Invention
Embodiments of the present invention generally relate to managing pressure within a wellbore. More specifically, embodiments of the present invention relate to managing pressure within the wellbore relative to pressure within a surrounding earth formation.
2. Description of the Related Art
To obtain hydrocarbon fluid production within an earth formation, a drill string is typically used to drill a wellbore of a first depth into the formation. The drill string includes a tubular body having a drill bit attached to its lower end for drilling the hole into the formation to form the wellbore. Perforations are located through the drill bit to allow fluid flow therethrough.
While drilling with the drill string into the formation to form the wellbore, drilling fluid is circulated through the drill string, out through the perforations, and up through an annulus between the outer diameter of the drill string and a wall of the wellbore. Fluid is circulated within the wellbore to make a path within the formation for the drill string, to wash cuttings obtained from the earth due to drilling to the surface, and to cool the drill bit.
After the wellbore is drilled to the desired depth by the drill string, the drill string is removed from the wellbore. Sections or strings of casing are then inserted into the wellbore to line the wellbore. The casing is typically set within the wellbore by flowing cement into the annulus between the outer diameter of the casing and the wall of the wellbore. The drill string is then lowered through the casing and into the formation to drill the wellbore to a second depth, and an additional section or string of casing is lowered into the wellbore and set therein. The wellbore is drilled to increasing depths and additional casings set therein to the desired depth of the wellbore.
During the drilling and casing process, it is important to control the pressure within the wellbore (“Pw”). Pw is controlled with respect to the pressure within the formation (“Ppore”). The well is balanced when Pw is equal to Ppore.
When Ppore greater than Pw, the well is underbalanced. Underbalanced is conditions within the wellbore facilitate production of fluid from the formation to the surface of the wellbore because the higher pressure fluid flows from the formation to the lower pressure area within the wellbore, but the underbalanced conditions may at the same time cause an undesirable blowout or “kick” of production fluid through the wellbore up to the surface of the wellbore. Additionally, if the well is drilled in the underbalanced conditions, production fluids may rise to the surface during drilling, causing loss of production fluid.
When the reverse pressure relationship occurs such that Pw is greater than Ppore, the well is overbalanced. Overbalanced conditions within the wellbore are advantageous to control the well and prevent blowouts from occurring, but disadvantages often ensue when Pw becomes substantially greater than Ppore. Specifically, the drilling fluid used when drilling the wellbore may flow into the formation, causing loss of expensive drilling fluid as well as decrease in productivity of the formation. Moreover, if Pw is substantially greater than Ppore, the drill string lowering into the wellbore may stick against the wellbore wall due to the drill string being pulled in the direction of fluid exiting into the formation, termed “differential sticking.” Typically, differential sticking of the drill string has been addressed by physically jarring the drill string or by fishing the drill string from the wellbore.
The desirable pressure relationship between Pw and Ppore varies in different situations. However, to avoid the disadvantageous results described above when drilling substantially overbalanced or substantially underbalanced, it is desirable to control Pw to be substantially equal to Ppore.
Generally, in a controlled wellbore, fluid pressure within the wellbore is maintained at a level above Ppore of the formation and at the same time below the fracture pressure (“Pfrac”) of the formation. The Ppore of the formation is the natural pressure of the formation. The Pfrac of the formation is the pressure at which the drilling fluid fractures and enters the formation. The controlled wellbore maintains a relationship between Pw and Ppore which prevents production fluid from entering the wellbore from the formation (by keeping Pw above Ppore) and at the same time prevents drilling fluid from entering the formation (by keeping Pw below Pfrac).
Attempts to control Pw take a variety of forms. Circulating drilling fluid within the wellbore while drilling with the drill string, along with its other advantages described above, affects the pressure within the wellbore. Flowing a sufficient volume of fluid into the wellbore at a sufficient flow rate and pressure may help prevent production fluid from flowing into the wellbore from the formation during drilling. Fluid properties of the drilling fluid such as density and viscosity also affect the pressure within the wellbore. Preferably, drilling fluid has a pressure at, but not above, Ppore.
Controlling Pw when the variable of drilling fluid is involved is difficult because of the nature of fluid flow within the wellbore. With increasing depth of the wellbore within the formation, fluid pressure of drilling fluid within the wellbore correspondingly increases and develops a hydrostatic head which is affected by the weight of the fluid within the wellbore. The frictional forces caused by the circulation of the drilling fluid between the surface of the wellbore and the deepest portion of the wellbore create additional pressure within the wellbore termed “friction head.” Friction head increases as drilling fluid viscosity increases. The total increase in pressure from the surface of the wellbore to the bottom of the wellbore is the equivalent circulation density (“ECD”) of the drilling fluid. The pressure differential between ECD within the wellbore and Ppore at increasing depths can cause the wellbore to become overbalanced, inviting the problems described above in relation to substantially overbalanced wells. The difference between ECD and Ppore can be particularly problematic in extended reach wells, which are drilled to great lengths relative to their depths.
In addition to altering drilling fluid properties and/or flow rates in the attempt to control Pw with respect to Ppore, sections or strings of casing are placed within the wellbore at intervals to help control Pw with respect to Ppore. Conventionally, a section of wellbore is drilled to the depth at which the combination of hydrostatic and friction heads approach Pfrac. A section or string of casing is then placed within the wellbore to isolate the formation from the increasing pressure within the wellbore before drilling the wellbore to a greater depth. When drilling extended reach wells, placing more casing strings or casing sections of decreasing inner diameters within the wellbore at increasing depths causes the path for conveyance hydrocarbons and/or running tools within the wellbore to become very restricted. Some deep wellbores are impossible to drill because of the number of casing sections or casing strings necessary to complete the well.
Along with setting casings into the wellbore and altering drilling fluid properties and flow rates from the surface of the wellbore to control Pw, other methods have been explored in attempts to control Pw (including ECD). Specifically, a choke or other type of flow control device has been utilized at the surface of the wellbore to increase and decrease Pw. Attempts to choke flow at the surface are documented in U.S. Patent Application Publication No. 2003/0079912 and PCT Patent Application Publication Number WO 03/071091, which are both incorporated herein by reference in their entireties.
When using a valve to choke fluid flow at the surface during drilling, high wellhead pressure results. High wellhead pressure exerted on a blowout preventer (“BOP”) increases strain on the equipment and could result in unsafe conditions due to lack of pressure barrier between the wellbore and the surface, possibly leading to shutdown of the operation at least for the time necessary to accomplish replacement of the BOP. There is a need to more effectively control Pw without compromising the effectiveness of the BOP.
Many variables which affect the pressure of drilling fluid within the wellbore exist while drilling into the wellbore, including the motion and effect of the drill string while drilling into the formation, the nature of the formation being drilled, and the increasing ECD and hydrostatic pressures which accompany increasing depths. The largely unpredictable effects of these variables cause the wellbore pressure to constantly change, especially with increasing depth within the wellbore. The current efforts to control Pw have largely depended upon manipulating Pw from the surface of the wellbore, while the pressure of the drilling fluid within the wellbore constantly changes as the drilling fluid increases in depth. Because the drilling fluid downhole and its resulting pressure are difficult to predict, controlling the wellbore pressure downhole from the surface is not very exact.
An additional problem with controlling Pw when drilling results because of the increasing pressure of fluid with increasing depth, or the sloped pressure gradient. Formation fluids within the interstitial spaces in the formation may not be adequately pressurized at one depth but too pressurized at another depth, so that the well is underbalanced at one depth and overbalanced at the other depth. Controlling Pw with respect to Pf at one depth may not control Pw with respect to Pf at another depth because of the increasing pressure of fluid with increasing depth. The attempts to control Pw from the surface of the wellbore do not address the dynamic nature of the wellbore at different depths, as formation fluids are not consistently pressurized at different depths of the wellbore. Depending upon the depth of the wellbore, it can be impossible to maintain adequate wellbore pressure control throughout the wellbore without exceeding Pfrac under normal circumstances.
Foam is a type of drilling fluid which is used to transport cuttings, which are by-products of drilling into the formation, out of the wellbore to the surface of the wellbore. Foam is generally a gas in liquid dispersion stabilized by the inclusion of a foaming agent such as a surfactant. Ideally, gas is dispersed throughout the liquid to form a homogeneous gas-in-water emulsion. The gas is dispersed in the liquid as a discontinuous phase of microscopic bubbles, and the foaming agent holds together the gas and the liquid.
Because of its performance at high viscosity, favorable rheological behavior (flow behavior), and low fluid loss into the formation even without adding fluid-loss additives, foam is sometimes preferred for use as a drilling fluid. Additionally, foam advantageously possesses structural integrity in a given flow regime, is lightweight, has low hydrostatic head, and boasts excellent suspension of solids in a defined flow regime. The ability of foam to carry cuttings from bends in a wellbore or a washout within a wellbore where cuttings often rest and remain, typically causing the cuttings to exist beyond the reach of liquid drilling fluids, is another reason foam is sometimes preferred.
However, foam flow properties, including viscosity and shear strength of the foam, must be monitored and controlled while the foam is within the wellbore to maintain the cuttings-carrying capacity of the foam up to the surface of the wellbore. The cuttings-carrying capacity and flow properties of foam are dictated in one respect by the foam quality of the foam. In a typical wellbore, foam quality varies as the foam travels through the drill string, as well as when the foam travels up through the annulus between the drill string and the wellbore or the surrounding casing. Foam quality, which is defined as the ratio of gas volume to foam volume at a given pressure and temperature, is an important property of foam because the closeness of the gas bubbles to one another within the foam determines the ability of the foam to lift the cuttings to the surface of the wellbore without the cuttings falling through spaces in between the gas bubbles. The foam quality parameter dictates whether the foam has fallen outside of the range in which the mixture is a foam.
The use of foam is often problematic because the flow behavior of foam is almost impossible to accurately determine due to the expansion of foam as it travels up the annulus. It is desirable to maintain a substantially homogenous foam flow regime in the annulus. If the foam quality and other behavioral flow properties of the foam deviate outside of a given range, the cuttings-carrying ability of the foam is compromised and may result in insufficient removal of the cuttings from the wellbore. Currently, only an estimate of the pressure profile and resulting foam quality along the annulus of the wellbore is possible because pressure within the annulus is dependent upon the bottomhole pressure, hydrostatic head, friction pressure loss in the drill string and other tubulars, and expansion of the foam in the annulus, and only the bottomhole and surface pressures of the foam are known. Attempts to maintain foam quality in the annulus involve estimating foam quality by measuring pressure at the bottom of the wellbore, then estimating pressure in the annulus at depth intervals by calculations to obtain the desired wellhead pressure for maintaining cuttings-carrying capacity. Therefore, knowledge of the flow regime of the foam is effectively “lost” while the foam is traveling up through the annulus, in between the bottom of the wellbore and the surface of the wellbore, compromising effective cuttings removal. The publication “Formation Fracturing with Foam” by Blauer and Kohlhaas, SPE Paper No. 5003, copyright 1974, which describes the prior art method of estimating pressure and foam quality along the annulus with only a known bottomhole pressure, is herein incorporated by reference in its entirety.
There is therefore a need to more effectively and dynamically control pressure within the wellbore while drilling into the wellbore. More specifically, there is a need to control the pressure within the wellbore at various depths within the wellbore. There is a need to maintain well control at all depths of the wellbore by manipulating pressure within the wellbore. There is a further need to tailor a wellbore pressure profile for use during drilling. There is yet a further need to maintain a substantially homogenous foam flow regime in the annulus when foam is used as a drilling fluid to preserve cuttings-carrying capacity of the foam along the entire annulus.